Wellhead test systems are widely used in the oil and gas industry. A wellhead test system determines the amount of gas, oil, and water produced by a given well that penetrates a subterranean reservoir in which such natural resources reside. Data from the wellhead test system (or “well test system” or “test system”) may be used to determine whether any properties of the reservoir or the resources therein have changed over time. The test data also may be used to allocate well production in situations where multiple wells feed a unitary production separator that separates all of the natural resources recovered from the region where the wells are located. The wellhead test data also may be useful where one production area handles wells from different taxation regions and production must be allocated to the particular field from which it originated. Various multiphase systems are available which measure oil, water and gas content of a production well without separation. These systems are expensive and can contain dangerous radioactive sources.
Well tests are usually expected to be reproducible with limits more or less defined by the company or government entity requiring them. Many applications may allow reduced accuracy of measurement due to low quality oil, cost of measurement and government relaxing of rules to allow more oil production in unfavorable markets. Several companies have addressed these at the well head measurements with unconventional solutions which still require acceptance of large errors and inability to confirm compliance to uncertainties required.
The use of real-time analyzers, such as density analyzers, capacitance analyzers, radio frequency (RF) analyzers, and microwave analyzers, to measure the water content of petroleum products is common. A single well is typically tested for 4 hours to 24 hours per well and only the gross totals of oil, water, and gas are maintained for the test. The same well may not be re-tested for changes until the remaining wells have been cycled through the well test separator system.
In conventional well test systems that measure the amounts of gas, oil, and water produced by a well, a gas separator first separates the gas from the three-phase mixture coming from the well. The well test system then measures gas and liquid flow rates. Next, the well test system measures the water content (%). The water content may be determined, for example, by measuring density or by using a permittivity method (e.g., RF or microwave). Many separators do not remove all of the gas and, therefore, 10% or greater gas volume fraction (GVF) may be seen at the flow meters and water analyzers. Conventional systems cannot separate the data to determine gas volume percent or water percentage because of the entrained free gas.
Real-time data provides several beneficial operational advantages. Measurement of gas, oil, and water as they are being produced at the wellhead eliminates many valves, large vessels, and radioactive sources while producing real-time well data (instead of one test per week or month for that well). In a situation such as steam assisted gravity drain (SAGD) production, the performance of a well may change considerably in a short period of time. In order to maximize production and maintain cost effectiveness, real-time well performance data is very important to well operators.
Current Method Issues
Wellhead test systems that measure density (e.g., a Coriolis flow meter) are adversely affected by entrained gas. The gas acts like a shock absorber and forces the Coriolis meter to increase the drive gain to compensate for the loss in ability to vibrate the tubes of the Coriolis meter. Although a measurement of mass can usually be made even at higher GVF, the volume and density are affected by the entrained gas. This gives poor density measurement. Some equipment makers use the drive gain to assist in the correction for entrained gas. However, one problem with this approach is that the drive gain and density are highly correlated and therefore another variable is required to achieve good correction.
Water analyzers are affected by gas in both water and oil emulsion phases. In both emulsion phases, the affect appears as if more oil is being produced than is actually produced. This is more pronounced in the water phase due to the gas looking like oil. A one percent (1%) gas volume fraction (GVF) appears to give 1% error in apparent water percentage. In the oil phase, the oil and gas both appear to have low polar moments, with the water still being seen by the system.
Therefore, there is a need to measure the production of oil, water, and gas at a well—without separation—in order to have real-time information that may be used to determine what the well is producing. There is a need to reduce the amount and cost of equipment that provides the real-time information. There is a further need for a wellhead test system that allows full-time well data instead of flowing the output of one well at a time through a multiphase system.